Vietnam Assets

This thread has been created to discuss the Vietnam assets. These currently consist of:

a) CNV - an operating field in block 9-2 with 155mn boe of gross 2P reserves

b) TGT - a field which is about to enter development. Gross 2p recoverable reserves of 300+mn boe (management think it will ultimately be closer to 500mn) should be confirmed soon, as the final government approval for the development plan is now very close.

c) TGD and the rest of the HPHT appraisal area - huge exploration potential of over 1bn boe P50 recoverable

d) VT appraisal area - a small discovery area likely to be relinquished

I'll fill in more details in due course.

ee

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SOCO International plc is a United Kingdom-based oil and gas exploration and production company. The Company has oil and gas interests in Vietnam, which includes Block 9-2 and Block 16-1; Republic of Congo (Brazzaville), which includes Marine XI Block and Nanga II A; the Democratic Republic of Congo (Kinshasa), consisting of Block V and the Virunga National Park, and Angola, consisting of Cabinda Onshore North Block. The Company's operations are located in South East Asia and Africa. It holds its interests in Marine XI and the Nanga II A Blocks in Congo (Brazzaville) through its 85%-owned subsidiary, SOCO Exploration and Production Congo SA (SOCO EPC). It holds its interests in the Democratic Republic of Congo (Kinshasa) through its 85%-owned subsidiary SOCO Exploration. It also holds a 60% working interest in the Mer Profonde Sud Block, offshore Congo (Brazzaville) through its wholly owned subsidiary, SOCO Congo BEX Limited. more »

Duri, Cabinda and Su Tu Den. The names are far more exotic, and less known, than Brent, the oil benchmark closely watched by investors around the world. But these crude streams are at the centre of a supply-demand struggle that is propelling oil prices higher.

The three varieties of crude oil, produced in Indonesia, Angola and Vietnam respectively, have are viscous and have a low sulphur content: in the jargon of the industry, they are “medium-heavy” and “sweet”. They are also in strong demand.......

Medium-sweet and heavy-sweet crudes account for a relatively small share of the global pool of crude supplies.

According to the World Oil and Gas Review published by Italian oil company Eni, their combined production last year reached roughly 10m b/d, or about 11 per cent of global oil supply. But the Japanese buying spree is reverberating well beyond heavy-medium and sweet crude, helping to push the whole oil market higher, traders say.

No specific reference to TGT, unfortunately, but that seems a bit of an omission - given that the article refers to Cabinda oils having a (paltry) $1.50 premium to Brent.

Some thoughts on why TGT phase 1 is being a tad tardy on ramping upto 55k a day.

The TGT Field is comprised of numerous separate accumulations some of Early Miocene age and others of Upper Oligocene age. The reservoirs are composed of normally pressured, vertically stacked sand layers with limited distance between production zones and oil-water contacts. Vertical well-bores through the reservoirs are designed to allow the use of technology like sliding sleeves, and the development well trajectories will avoid extremely high angle step-outs as regular wireline intervention work is expected.

Its worth reading the above a couple of times. I copied it from Hoang Long Joint Operating Company site that Spurticus brought to our attention yesterday. Go back over these boards and others this year and you will see that many posters think the Soco might have production issues by not reaching 55k production within very early days of initial flow. This immediate production at the higher end of the anticipated flows would be unusual and a couple of thoughts come to mind from the wording from that paragraph above.

I do not know of the production and completion arrangement on these particular wells. I do have experience with Shell and Exxon in other parts of the South China Sea. These two companies have drilled many hundreds of wells, probably having similar geology and completion logistics to Soco. Even with this experience bringing a multiple well completion on to production is still a challenge. One side of the company operation wants to maximise production through a fast and cheaper completion arrangement. Others will look at the multiple zones of interest and will be aware very early on in the programme that a partial production programme is the most realistic avenue to follow to provide long term steady production.

''the use of technology like sliding sleeves, and the development well trajectories will avoid extremely high angle step-outs as regular wireline intervention work is expected' This comment suggests that Soco have elected to go the last route. I would read the wireline intervention as a procedure to bring on production zones in a timely manner. In a perfect world all the zones of interest would be flowed as per the initial tests that gave rise to the 55k figure so loved by one and all. In practice (and as the management well know - and others wanting a slice of Soco will know) the production ceiling is a step route. Somedays higher and some days lower. But, as the months go by a lot of information is being captured to create a reservoir programme for long term production based on the downhole conditions and not just market expectations.

''the use of technology like sliding sleeves, and the development well trajectories will avoid extremely high angle step-outs as regular wireline intervention work is expected'

This comment suggests that Soco have elected to go the last route. I would read the wireline intervention as a procedure to bring on production zones in a timely manner. In a perfect world all the zones of interest would be flowed as per the initial tests that gave rise to the 55k figure

If I may offer a slight correction to the implication of the above: if ALL zones of interest were perforated and flowed then production would be considerably higher than 55k bopd.

Obviously that was never a practical consideration, but the original plan (to perf the more productive Miocene) was delayed due to a wish to obtain more data about the Oligocene (and determine whether a further well would be needed in due course to drain that reservoir)

The 55k figure is the rated capacity of the FPSO, as presently configured (with 75k bpd of water-handling capacity). Perfing the Miocene in the main wells that were planned would (guessing) give more like 70k bopd capacity if all wells were fully onstream (they would likely add around 10,000 bopd per well, judging from test flow rates).

The key decision on the route to monetisation is to determine how best to produce when H1 and H4 are both fully operational and on plateau. And, in that context, testing the wells exhaustively is quite important for assessing (for example) water-handling needs - because one option would be to convert a chunk of water-handling to oil storage. Another option would be to produce across Bach Ho....or to hire in another FPSO. Whatever the decision, we are now getting close to the point where that decision can finally be made, with H4 likely to come onstream in July. Reaching 55k will then be extremely straightforward, with underlying potential capacity of close to double that amount from all the producing wells....and we should shortly have an idea of the H1+H4 plateau capacity.

I have been trying to understand where we stand on the route and the likely timing to monetisation.

My career was in the non ferrous metals mining industry where the route to monetisation would often follow the steps outlined below :

A) drill the resource ,construct a model and determinine an ore reserve
B) consider various mining methods and determine the mining reserve ( less than the ore reserve)
C) estimate the recoveries in the mining operation and the downstream processes to the final product
D) prepare a DCF model based on estimated revenues, capex and opex

I have been trying to draw analogies with the above to see where we are at present, particularly with regards to having a good estimate of the potential recoverable reserves from TGT.

I assume that the production data from the Phase I production wells has increased confidence in the reserve estimate in that portion of the reservoir.

Similarly drilling of the 5 wells in Phase II will have added to the information on the reservoir. However won't it be necessary to have production data from these wells to really define the recoverable reserves ? If so , how much time would be needed to obtain the necessary information ?

I also noted from page 15 of the Annual Report (the last para dealing with Block 16-1 ) that significant additional potential remains to be confirmed in undrilled and un-appraised fault blocks and the company is seeking to accelerate the drilling of these areas. Are these the areas that could increase the reserves to the 500 million barrels I have seen mentioned elsewhere ?

I hope my comments will not be dismissed out of hand as they come from someone without oil industry E & P experience as I would I would welcome advice on the concerns I have expressed.

I assume that the production data from the Phase I production wells has increased confidence in the reserve estimate in that portion of the reservoir.

Similarly drilling of the 5 wells in Phase II will have added to the information on the reservoir. However won't it be necessary to have production data from these wells to really define the recoverable reserves ? If so , how much time would be needed to obtain the necessary information ?

Imo (non-tech) yes...maybe a few months

I also noted from page 15 of the Annual Report (the last para dealing with Block 16-1 ) that significant additional potential remains to be confirmed in undrilled and un-appraised fault blocks and the company is seeking to accelerate the drilling of these areas. Are these the areas that could increase the reserves to the 500 million barrels I have seen mentioned elsewhere ?

Yes. However, the recovery factor is also an important issue in determining reserves. AIUI, Soco have booked their reserve numbers at the lower end of the expected scale with early results showing something better than this. One imagines Phase 2 will come under the same productive scrutiny. As to undrilled blocks, consideration arises as to whether full field reserves can be produced before licence expiry. To this end, imo, it will be absolutely crucial to expand production facilities (or hook into Bach Ho) to fully exploit the field within the timeframe available. Although options are on the table, no decision has been made to date but I don't see Soco selling until such plan has been decided upon, one way or the other. That said, any buyer is free to make their own risked reserve assessment at any point in time and put an offer on the table.

As you said the recovery factor has a major impact on determining the reserves and this leads me to thinking that several months of production data from the Phase II wells will be needed to etsablish an overall recovery factor.

I hadn't realised the need to expand production to fully exploit the field within the timeframe available - thanks for pointing that out.

Having attended AGMs for several years I am sorry that I will be away for this one but I assume that questions on the timing of reserve updates and production expansion plans will be raised from the floor.

Finally, do you have any thoughts on what may be covered in the forthcoming IMS ?
.

drilling of the 5 wells in Phase II will have added to the information on the reservoir. However won't it be necessary to have production data from these wells to really define the recoverable reserves ? If so , how much time would be needed to obtain the necessary information ?

Hi Highgate,

I've highlighted an important phrase. The only way that one can achieve certainty over the reserves of any field is to actually go through the whole production cycle and produce all the oil and gas that one can. That would take perhaps 20 years.

So....we aren't going to achieve certainty. And your question reduces to "how long before uncertainty has been reduced to acceptable levels"......and it is THAT question which lies at the heart of the debates over timing - because there is no single answer.......it mainly depends on the views of potential acquirors.

As you know, I've been expecting a buyer to jump in at an earlier stage than many have assumed. But that hasn't happened - presumably mainly because (until recent weeks) SOCO harboured reasonable hopes for significant TGD upside. So, to answer your question as I have redefined it, the question is what milestones remain to be passed before (probably, because no-one can be certain) buyers can achieve acceptable levels of certainty?

Davjo points to one here:

it will be absolutely crucial to expand production facilities (or hook into Bach Ho) to fully exploit the field within the timeframe available. Although options are on the table, no decision has been made to date but I don't see Soco selling until such plan has been decided upon, one way or the other. That said, any buyer is free to make their own risked reserve assessment at any point in time and put an offer on the table.

....so...starting there and expanding the list, I would say that these could all be important milestones:

Agreement on producing 55-60k bopd over existing facilities and on associated perforation plans for individual wells (may already have happened and be awaiting execution)

Quantifying the fluids production from CNV and agreeing final prices for gas and fluids. This will result in an increase in reported fluids production and the pricing would be backdated to 2009 (worth $50-100mn to SOCO IMO and likely to be achievable within a few weeks, since the separator was due to come online in May)

Confidence about start-up of H4 production date in July or August (loading topsides out should happen this month)

Reserves upgrades calculatable, arising from production experience and phase 1 and 2 drilling results linked with the 2009 PSDM seismic (70% of any upgrade should currently be achievable and a further 20% when H4 production starts and other zones on the H1 wells are perfed, IMO)

I don't think that anything else is actually crucial for a deal. Yes it would be nice to have drilled the undrilled H5 fault block (for example) as that is thought to be around 200mn bbls OOIP - so perhaps 80mn gross recoverable......or c. 20mn net to SOCO. It would be nice to have such things - but I would think that someone would be happy to give at least some value for the potential upside there, even now. The 500mn bbl number is, IMO, mainly going to be down to estimates of the recovery factor - and the company has indicated 40-50+% has been estimated from observed data so far. I believe that this factor on its own could justify a reserves upgrade of around 40% at TGT, if substantiated by the initial production tests on the H4 wells.

It remains my opinion that a deal will be done over the summer months, even though the path to the production plateau remains more unclear than I had originally expected by this time.

Many thanks for identifying the milestones you consider necessary to make a reliable estimate of the reserves.

Am I correct in thinking that if there is a hold up in raising TGT's processing capacity beyond 55k bopd they can always shut down production from the HI wells while they carry out production tests on the H4 wells ( on the basis that hooking into Bach Ho or providing another FFSO is only a matter of plumbing ) ?

I appreciate the responses from you and davjo and believe I should better able to assess both the content and value of information in the forthcoming IMS and future releases from the company.

Am I correct in thinking that if there is a hold up in raising TGT's processing capacity beyond 55k bopd they can always shut down production from the HI wells while they carry out production tests on the H4 wells ( on the basis that hooking into Bach Ho or providing another FFSO is only a matter of plumbing ) ?

I wouldn't downplay the significance of either hooking into Bach Ho or getting another FPSO. Either are major investment decisions that won't be completed overnight. But, as davjo pointed out, it is the agreement to implement a clear decision/plan which is the key point in the process - and from then on it is a multi-month project to install. Once that decision is taken, then it should be quite clear what the production capability of TGT will be.

In the meantime, you are right that they have flexibility to get to 55k bopd by producing from different wells whilst they test and perforate different horizons.

HLJOC, PVC-MS and the subcontractors are effectively executing the offshore work including transport, installation, hook-up, and commissioning to target the first oil from WHP-H4 in July 2012, one month earlier than the plan by the Block 16-1 Petroleum Contract Management Committee and 11.5 months earlier than the Early Development Plan, approved by the Ministry of Industry and Trade.

After reaching peak output of 263,000 bbl/d in 2003, the field’s production dropped to an average 92,000 bbl/d in early 2011. It is expected that Bach Ho’s production decline rate will range from 20,000 bbl/d to 25,000 bbl/d through 2014.

Yes I look forward to hearing what the management have planned for P2 production, and whether anything has been done to the fpso re water capacity, or if there are plans to tie in to Bach Ho infrastructure. I'm not sure how far the tie in point would be but I would have thought that longer term it would probably make more sense to tie in to Bach Ho, is Phase 1 much futher way or is there some other reason not to link that into the same network ?

Do you have more info on this ee ? is the expense in linking in the pipeline, or is it to do with paying the owners of the infrastructure for it's use ? Once linked you would expect the real costs of using a pipeline to be much lower than the fpso solution, of course it may not be so in terms of the cost to soco, and I guess it depends where the oil is being shipped to, if it's being taken to vietnam then the pipeline makes more sense, if it's going elsewhere then it will still need to be loaded to a tanker anyway. (any idea what magnitude of cost difference there is ?)

I assume that PV have ownership or a share in the Bach Ho infrastructure, so they may well have a preference for using this solution, and paying a higher price, (since some of that price goes to them), I wonder if this is one of the issues causing the slow ramp up and perhaps the compromise we will have to live with, in order to get tgt production above 55k. I presume we are talking about fractions of a dollar per barrel or there abouts ?

Will be interested to hear what is said about the plans to handle capacity beyond the much discussed 55k,

Do you have more info on this ee ? is the expense in linking in the pipeline, or is it to do with paying the owners of the infrastructure for it's use ? Once linked you would expect the real costs of using a pipeline to be much lower than the fpso solution, of course it may not be so in terms of the cost to soco,

Yes - but nothing reliable enough to quote. Suffice to say that the capital costs would certainly be more expensive (tens of mns) - and I guess one should assume that there would be a bigger bite out of operating margins too due to tariffs.

Not at all clear which way will ultimately be picked or what the net costs/benefits would be. Will all have to wait to see the plans I guess.